Burned by an aborted nuclear power plant new build that saddled the state's consumers with hundreds of millions of dollars in needless costs for years to come, South Carolina's Act 187 established a legislative study committee to ponder whether the state's electricity consumers might not be better off with competitive reforms of the Palmetto State's 150-year-old monopoly regulatory regime. A centerpiece of the committee's considerations is a sweeping analysis of the competitive options the state could pursue, comprehensively put together by the Brattle Group.
We talk with two of the report's authors – John Tsoukalis, principal, and Andrew Levitt, senior consultant, at the Brattle Group – about their report with the top-line conclusion that South Carolina electricity consumers could save up to $300 million annually if the state's utilities participated in some form of large regional transmission pooling organization. The biggest cost savings, they determined, among the various scenarios considered in the report, were projected from a scenario envisioning if the entire Southeast region, not just South Carolina, were to throw in with PJM Interconnection, the large regional transmission operator encompassing from Illinois across to Pennsylvania, New Jersey, Maryland (PJM) and Virginia, in order to create a large, diverse wholesale power marketplace that helps minimize the considerable costs of meeting resource needs and operating a reliable powergrid.
As directed by Act 187, the Brattle analysis also examined the potential consumer savings available from conducting a consolidated statewide integrated resource planning (IRP) process, rather than the less efficient utility-by-utility IRP planning that the state's utilities undertake with regulators to determine development or acquisition of new generation resources to meet reliability needs – and then performing competitive solicitations to help develop any new resources.
Also as required by the law compelling Brattle's analysis, the report delved into the Third Rail of electricity politics: restructuring utility regulatory oversight to provide some form of competition in retail sales to consumers, whether residential or the large industrial and commercial customers. "Part of what I guess people don't really understand is, you can't really do retail choice unless you have competitive wholesale markets that are working already," Tsoukalis explains, calling the potentially near-term savings from grid regionalization the "low-hanging fruit" of the options available to lawmakers to consider going forward.
"There's so many options" in the report for lawmakers to consider, Levitt notes. "You can take a mix-and-match approach, different ways through governance, different ways to do transmission planning. You can share these things and not share those things. I'm 100% confident that there's a solution out there that will match the political will that's present at the moment. I don't myself know what the solution will be, but we're available to help craft it."
Burned by an aborted nuclear power plant new build that saddled the state's consumers with hundreds of millions of dollars in needless costs for years to come, South Carolina's Act 187 established a legislative study committee to ponder whether the state's electricity consumers might not be better off with competitive reforms of the Palmetto State's 150-year-old monopoly regulatory regime. A centerpiece of the committee's considerations is a sweeping analysis of the competitive options the state could pursue, comprehensively put together by the Brattle Group.
We talk with two of the report's authors – John Tsoukalis, principal, and Andrew Levitt, senior consultant, at the Brattle Group – about their report with the top-line conclusion that South Carolina electricity consumers could save up to $300 million annually if the state's utilities participated in some form of large regional transmission pooling organization. The biggest cost savings, they determined, among the various scenarios considered in the report, were projected from a scenario envisioning if the entire Southeast region, not just South Carolina, were to throw in with PJM Interconnection, the large regional transmission operator encompassing from Illinois across to Pennsylvania, New Jersey, Maryland (PJM) and Virginia, in order to create a large, diverse wholesale power marketplace that helps minimize the considerable costs of meeting resource needs and operating a reliable powergrid.
As directed by Act 187, the Brattle analysis also examined the potential consumer savings available from conducting a consolidated statewide integrated resource planning (IRP) process, rather than the less efficient utility-by-utility IRP planning that the state's utilities undertake with regulators to determine development or acquisition of new generation resources to meet reliability needs – and then performing competitive solicitations to help develop any new resources.
Also as required by the law compelling Brattle's analysis, the report delved into the Third Rail of electricity politics: restructuring utility regulatory oversight to provide some form of competition in retail sales to consumers, whether residential or the large industrial and commercial customers. "Part of what I guess people don't really understand is, you can't really do retail choice unless you have competitive wholesale markets that are working already," Tsoukalis explains, calling the potentially near-term savings from grid regionalization the "low-hanging fruit" of the options available to lawmakers to consider going forward.
"There's so many options" in the report for lawmakers to consider, Levitt notes. "You can take a mix-and-match approach, different ways through governance, different ways to do transmission planning. You can share these things and not share those things. I'm 100% confident that there's a solution out there that will match the political will that's present at the moment. I don't myself know what the solution will be, but we're available to help craft it."
EMP S3E13: Brattle Group’s John Tsoukalis and Andrew Levitt
(transcript edited for clarity)
EMP: Welcome to the Energy Markets Podcast. Today we’re going to talk about the potential economic benefits of introducing competitive reforms into the electricity markets in the U.S. Southeast. With us are John Tsoukalis, principal with the Brattle Group, a respected international consulting practice, and Andrew Levitt, a senior consultant at Brattle, who were among the authors of a comprehensive report prepared for a South Carolina state legislative panel examining how introducing competitive reforms – at both the wholesale and retail levels – potentially could realize hundreds of millions of dollars in economic savings. John, Andrew, welcome to the podcast.
AL: Thanks, Bryan.
JT: Thanks for having us.
EMP: So you gentlemen and your colleagues prepared a report for this South Carolina legislative committee – the study committee of the South Carolina General Assembly. You found in this analysis $300 million in annual savings if South Carolina participated in an organized regional wholesale power market. That's the top line of your press release. But I think having South Carolina participate in a regional market is just one of the proposals you looked at. Can you guys peel back the layers on this $300 million onion for us?
JT: Sure. That number, that $300 headline number is our estimate of operational benefits from being part of a regional wholesale market for power. Now that can take many different forms. Being part of a regional wholesale market, the way we simulated it and modeled it, means joint unit commitment, joint dispatch, sharing transmission infrastructure between the members of the market and would probably mean being a member and an RTO. So, but it also can be it's be achieved, you know, without full membership in an RTO. So, it is it is the operational benefits of joining a regional wholesale market that would include the existing PJM footprint plus the Carolinas. So, we came up with that – that was the biggest number when we analyzed the PJM footprint with the Carolinas, but we also found that they could save almost $200 million a year by creating a similar market in the Southeast, which would include Southern Company – basically all of the members of the current SEEM market.
EMP: So you looked at different configurations of a market that the state could participate in, whether it be the current SEEM states, Southeast Energy Exchange Market states, or joining PJM. But in either case, it would require the participation of North Carolina.
JT: For those two configurations, yes. We didn't study a regional market that would only include the two entirely encompassing South Carolina balancing areas – Santee Cooper, and Dominion – because, you know, just with two utilities, the footprint is not quite that large. And we talked about that with the study committee in South Carolina. We we've expressed to them that you know, these kinds of regional markets work best when you have larger footprints. Only really large states like California, Texas, New York, have kind of single-state markets and even those, you know, probably would work better as larger markets.
EMP: No doubt they would. So, so each of the scenarios came up with different conclusions, but the most economically rewarding scenario would be joining PJM and creating a very large regional marketplace that way.
AL: Yeah, that's right. And that's really nothing to do with the policy outlook in PJM. It's just about weather. So you have largely Mid-Atlantic and to some extent Midwestern weather in PJM because it extends to the north and the northwest of South Carolina, and that weather is pretty different from the basically hot southeastern climate that South Carolina is in, versus SEEM is all across the Southeast. So when the Southeast is very hot or very cold, that's affecting South Carolina and the rest of the of that footprint. So that area has to sort of plan for that contingency all happening at once. If PJM is very cold, South Carolina might not be very cold. If South Carolina is very cold, as we saw in winter storm Elliot last December, actually, there's a lot of PJM that's not going to be very cold. It just has a different geography that encompasses different types of weather systems. And so there's more diversity and that shows up both in the operational savings and also in the resource adequacy or capacity-type savings.
EMP: So by expanding the footprint you get a lot more – economies of scale is not what I'm looking for – but you get the scale where you can kind of arbitrage the differing weather, different weather events within the regional footprint. You had a very involved process in doing this, you had an advisory board and you got feedback from them that kind of shaped the final report that you've put together here?
JT: Yes, that's right. The advisory board was actually determined by legislation. So, Act 187 is what created the study committee and funded this study in South Carolina. It also specified members of this advisory board. And for about a year – a little bit longer than a year, 14 months or so – we met on a somewhat regular basis with the advisory board, shared with them kind of our modeling approach, what reform options we were going to study and how we were going to study each of those. Got their feedback. Then they reviewed a draft of the report and gave us comments which are posted on the study committee website. And so those comments inform the final version. We shared preliminary results across the year. So it was, I would say, you know, a good interactive process with them.
EMP: Well, so we've talked about the wholesale market reforms to some extent. But you also looked at resource planning and expanding the footprint of IRPs (integrated resource plan) so that it's not just the utility-by-utility silo but having an IRP for the whole state?
AL: Yeah, we really looked at three big categories of reforms here. And so you're right, that first category of reforms we called wholesale market reforms. You could also think of that as basically technical reforms related to pooling lots of utilities and their operational needs and their capacity planning needs. The wider the area you do that – just because of the technical and economic arrangement of utilities and weather, as I mentioned – the more benefits you get. And that's really the bulk of that $300 million in annual savings is coming from that type of effect. The second category of reforms we looked at was competition in capacity procurement, or supply adequacy competition. So for example, if you're doing central planning at the utility level, and there's a decision to invest in new generation, rather than necessarily having self-build from the utility, you could have a policy that says, no, we're going to go out to bid and have a lot of different players bid to provide that capacity. So that's just an example of one of the reforms in that second category. And then the third category is reforms to the retail rules and the retail markets. An example there would be taking large industrial customers or towns that have their own electric utilities and giving them access to competition, into the markets, if they want to buy supply from folks other than the utility they're connected to. So those are the three big buckets. That first bucket is really the thrust of our recommendation in the sense that it's an immediate recommendation that we make that South Carolina join some kind of large pooling area, be it PJM, or starting a new Southeastern RTO. Or not joining an RTO at all, but actually performing something like an ad hoc pooling arrangement, like what you're seeing in the West, where a lot of utilities want to get that benefit of pooling, especially with more wind and more solar coming onto the system. It's difficult for them to operate and balance their systems independently. So they want to derive all those advantages but without necessarily joining the regulatory construct that comes along with an RTO. They want to share something with their neighbors but not necessarily sharing everything with their neighbors. And so our recommendation encompasses all of those alternatives and we really think it's the – we trust the legislation in South Carolina to pick the best among those and to be creative and in figuring out what the best fit is.
EMP: You're talking about a radical departure from what's there now, which is the early 20th century vertically integrated regulated utility monopoly that is the one extreme that we have here versus other states that have adopted competitive reforms already. Did you have a sense in your conversations with them that any of this was actually politically acceptable to them? Did they get what they wanted from you? Did they hear what they wanted from you?
JT: Yeah, that's a great question. Let me first say that we were very clear throughout this whole process that actually a radical departure doesn't really make sense at this point in time. It's been 25 years since any state has moved all the way from the traditional vertically integrated model to a fully deregulated one. You know, when restructuring happened in the ‘90s and early 2000s, you know, no state has done that since then in one fell swoop. There's more of an incremental model that is emerging now that is popular in the Western U.S. So if you went back 10 years ago, every state in the West, in the WECC, would have looked just like the Southeast except California. And now that's not the case. Now you have the Western EIM that encompasses 80% of the West. You have SPP, which has an imbalance market that encompasses essentially the rest of the West, you have the EDAM forming and you have Market+ forming. We see those as kind of incremental steps that allow you to capture some of these benefits we're estimating. In fact, something like the EDAM market with a WRAP style, which is the Western Resource Adequacy Program style, you know, resource adequacy market would give you exactly the same benefits we studied. But you wouldn't form an RTO, you wouldn't have joint transmission tariffs, you wouldn't have regional transmission planning and regional generation or connections. So there are incremental steps and that we were very clear with the study committee that that's what we're recommending. Get the benefits we know are there – kind of the low-hanging fruit from cooperating and pooling in a regional market – and then thinking about studying more competitive reforms down the road. So let me say that to start. And then to answer your direct question. Yes, I do think some of that stuff is politically achievable. Obviously, there are vested interests across the state and in the region that, you know, would either support or oppose market reform. But I think something like an EIM, something like an EDAM-style market is a middle-of-the-road compromise that, you know, the utilities would potentially find attractive. Because they can save some money and help balance their system for their customers, but doesn't always, you know, require them to join basically a full RTO. So I do think there are incremental steps like that that are feasible, within a near-term time horizon in South Carolina and in the Southeast. Let me say one additional thing there, is what we actually recommended that the state do and what I believe the study committee is now working on – Sen. (Tom) Davis and Rep. (Jay) West are the two chairs. I believe they are they said anyway to us in our last meeting that this is what they're going to do next – is that they should put together kind of legislation that lays out some broad principles, or you know, things that utilities could do to access some of these reforms, but then create a process and empower the PSC to have a public hearing on it and let the PSC decide what is the best way forward. We didn't think it the best way to make policy to have us come in and recommend something and the Legislature adopt it. That's not the best way to make policy. There should be an open public process where utilities can bring their preferred solution forward, you know, each utility can bring that forward, the cooperatives, the municipal utilities, customers, you know, ratepayer groups, all of these folks can bring their preferred solution forward and let the PSC decide what's the best way to reform the market and get the state to access these types of benefits for customers. That's actually what we recommended be done and that's what I think the study committee is working on now.
AL: This this is partly why I'm trying to draw the sharp distinction between pooling arrangements, which are basically technical and have to do with who's scheduling generators and what business processes they're using to schedule generators, and the market reforms that we recommended having to do with competition and ultimately sort of beyond the horizon of our recommendations, that kind of competitive reform could end up with full deregulation and generation divestiture as happened in some of the early RTO states. And I do think that kind of thing would be quite radical for South Carolina. I don't think joining an RTO is actually nearly as radical as that. Most of if you just count up the number of utilities in RTOS, there's a lot of little ones. Most of them are vertically integrated in traditionally regulated states. So RTOs are perfectly compatible with the traditional cost-of-service regulation model for utilities, and it just has to do with there’s the dispatcher sitting in my office or is the dispatcher sitting in somebody else's office. And if you're pooling a lot of utilities, you have to have an independent dispatcher so people know that there's somebody that they can trust and rely on and they're following impartial protocols. So that's just the first thing. I don't know that it's quite as radical as it sounds. If I think about for example, East Kentucky Power Cooperative, joined PJM in 2012. And they're a co-op. They're vertically integrated to the extent that co-ops are. And really they just said, Well, now, TVA, back in 2012, TVA was a reliability coordinator. They had a reserve-sharing arrangement with some other local utilities. Okay, now my reserve-sharing arrangement’s with PJM instead of the local guys and my RC (reliability coordinator) is PJM instead of TVA, and I'm saving a bunch of money on capacity because now I'm getting a share of PJM summer capacity peak instead of before I was planning to my winter capacity, which was like 50% higher than their summer peak. So they just saved a lot of money, had to rearrange their business processes a little bit. It was a real win for them. I could definitely see something like that working for South Carolina. I also want to say there's a lot of existing pooling arrangements already there that are they’re so undramatic and unexciting that folks don't even necessarily know about them. SEEM, of course, is the obvious example. SEEM has got a really wide footprint, which is great. It's starting, you know, it's the first that I can think of the first wide-area pooling that’s happening in the Southeast across the whole history of electricity in this country, which is a fantastic thing. It's starting with relatively easy-to-implement, relatively small functionality, which is like the super spot market of 15-minute and faster trades, but it's automatically matching buyers and sellers and that's what you want to see in a big pool. So hopefully they can expand that functionality and start to get some of the scale of benefits that you see with a more fully featured pooling arrangement. So there's SEEM. You've also got VACAR which used to include parts of Virginia. Now it's really just the Carolina utilities that are sharing some of their reserves, that they're sharing their liability coordination services. Effectively, Duke I think is their liability coordinator for all the utilities in South Carolina. So it's not like an entirely new concept to offload some of these business functions to another party in the interest of savings.
EMP: Yeah, well, thanks for that clarification. I didn't want to suggest that just simply the regionalization of the grid is the radical departure when that's the ultimate low-hanging fruit of your recommendations. But the package as a whole, you know, where you talk about competitive generation and competitive markets at retail, that's the radical departure. And but what I hear you guys saying is, this is like a menu of choices that they can consider. And that it's up to them as they move along to move incrementally, which you seem to be recommending, or to try and do it all in one fell controversial swoop, which I think is unlikely.
JT: Yeah, yeah, I would agree with your assessment that, A, it's unlikely, but, B, that that would be a radical change to do it in one fell swoop. And to be very clear, we're not recommending that at all. We actually have in the executive summary this little flowchart diagram, it’s Figure ES-1, that lays this out – that basically lays out the timeline and talks about, you know, these other reforms that have to happen first. Because part of what I guess people don't really understand is, you can't really do retail choice unless you have competitive wholesale markets that are working already. So our stance is, you know, let competitive, you know, retail choice, all that’s down the line that's, you know, at the end of the path, and maybe South Carolina finds that it's beneficial to go there, maybe it doesn't. But at the beginning of that path is also, you know, cooperation and pooling, a wholesale market. And so let's start at the beginning as opposed to starting at the end. And that's really that $300 million headline number. That's all about wholesale cooperation and wholesale pooling and markets. It's not about any benefits you could see from competitive investment in generation or transmission. It's not about retail choice. It's all about that first step – that wholesale market step. So that's where we – the study focused on that. And we talk a lot about that with the study committee, the legislators, over the course of the year. We laid out for them and a lot of these presentations, and they're all public. They're posted on the committee’s website. We laid out for them, this big spectrum. You know, there's kind of the traditional vertically integrated utility model on one side, and then you could think of, you know, the Texas ERCOT model on the other side, and we're not suggesting they move in one fell swoop to do the Texas model. In fact, we're not suggesting they ever move there. That's a question for them to decide later down the road. But what we are suggesting and recommending are kind of incremental steps towards more wholesale competition similar to what's happening in the non-California part of the WECC (Western Energy Connection) similar to the SPP model, let's say, where they have an RTO but the utilities are all vertically integrated and traditionally regulated at the state level. Or MISO, you know, every utility in MISO is vertically integrated and regulated by the state in the traditional way, except in Illinois, but all the other states that way. So those are kind of, in our view, incremental steps and that's what we're – that's where we focus our kind of our study and then the results that you see in the study are focused on.
EMP: I was interested in just the fact that you found benefits in retail market reforms. That seems to be not in vogue anymore, as you noted, John, that we haven't seen any, any real retail market reform since the Western energy crisis and California’s really bad market design crashed in a very high-profile way. But it seems to me there's two tranches of states with retail competition. There's Texas and all the others. And one of the things we've been discussing on this podcast is that it might be beneficial for the customers in the dozen or so states outside of Texas, and DC, to take a more of a Texas approach to the market in which the utilities are quarantined from the market. Do you guys have any thoughts on that?
JT: Yeah, so I would say, to be clear, we didn't calculate any benefits related to retail choice. Like I said, we didn't really focus our analysis on that because we see that as a later decision for South Carolina. It can't even make that decision until it has a wholesale market is our view. But we did discuss it in the report because it’s in the law. The legislation that created the study, funded the study, talked about those options and we wanted to address them. So we discussed kind of pros and cons, advantages, disadvantages, and we discuss those options qualitatively. But to answer your question, you know, our view on that is there's a mixed record in this country over the last 30 years about the benefits of, you know, retail choice for residential customers. You know, I don't think we've taken a hard stance in the report – we certainly don’t intend to – about whether that's beneficial or not. Residential customers, you know, like you said, in most states that have retail competition, they don't really even mean it. You know, most residential customers are still on the provider of last resort, the incumbent utility, like there's two types of retail choice in this country, for residential retail choice I should say. There’s states where they have it and they actually use it and states where that have it but don't really use it. And you know, maybe in the first category, it's probably only Texas and maybe Illinois or something like that. Everywhere else where they have retail choice it's basically the same utility that's been doing it for 150 years is still doing it now. So again, our view is that there's a mixed record on that. We're not saying that, you know, residential retail choice is something South Carolina should ever do. It's a question to be asked many years down the road if they wanted to go there. On the flip side, though, we do talk about what's called partial retail choice in the report, which is for large customers. I do think there is evidence from other jurisdictions that sophisticated buyers of power – so folks who use a lot of energy like steel mills, aluminum smelters, datacenter owners like the Googles and Facebooks of the world, those folks – not only is power a really big part of their business costs, but they also some of those folks have very specific preferences on power choices. They want green power, whatever the case might be, or they need for industrial processes certain levels of reliability that the residential customer doesn't need. Sophisticated buyers of power I do think there is evidence from other jurisdictions that retail choice can help them, that they can help lower their costs, you know, for industrial customers, which means generating economic activity. So we do say in the report that that's something South Carolina should think about. Again, you need to have a wholesale market in place first. And there are still pros and cons related to that, right. If you have big customers that exit the system to buy from a third-party provider, you got to make sure that they're not leaving behind a bunch of costs for everyone else to pay for, that stays on the utility system. So that's got to be regulated and that exit has to be designed properly with the right fees. So there are questions that need to be addressed there. But that is something we find is worth exploring. Based on the evidence in other jurisdictions, those kinds of really big power consumers can save a lot of money and do well under competition. But when we're talking about small businesses and residential customers, there's a real mixed bag historically.
EMP: Yeah, but you also talked about aggregation of these customers.
JT: That's right. Yeah. And, again, we don't explicitly recommend that South Carolina go there now, but Community Choice Aggregation was actually explicitly listed in Act 187. So we looked at it. As you probably know, there's really only one state in the union where that's a significant amount of the load now and that's California. And actually, it's a very large percentage of the load now in California. So again, that's something, you know, California has a wholesale market already. So that's step one, still, is wholesale markets and transparent competitive markets on the wholesale side to make aggregation work. So, you know, again, our recommendation to South Carolina is that that's something you can think about down the road. And again, if communities want to get together and do that, once you have a wholesale market in place, there might be benefits to that, but that's not part of any type of reforms that we think should be implemented at this moment, based on what we found and what we analyzed in this report.
EMP: You want to add to that, Andrew?
AL: Just a minor point. It's, you know, especially large customers, they're doing lots of procurement of all the inputs to their business. Electricity is one of the major inputs of their business. So they already have staff and processes set up to do this kind of procurement so that it's very effective to slot it in there. John mentioned they've got preferences about the source of their supply. They’ve probably got corporate sustainability goals. They want to save a buck, so you have a big procurement you get more than three bidders and people start to bid prices down. That's a real thing that actually happens. And then I would just add, the nature of the rate in terms of how much hedge am I getting and what is the strike price on the hedge and how am I going to be elastically interfacing with whatever the supplier’s price signals are. In a bilateral environment without RTO prices, there's less of that. But in an RTO, where you get a wholesale price at every single bus, including in many cases, an industrial load gets their own nodal price, they can make decisions day-by-day and hour-by-hour about what to do in response to that to that price and they can squeeze even more advantage out of that. So I would put sort of the nature of the supply agreement with the supplier, especially with large industrial customers, can save them quite a lot of money. I would think that the energy hedge cost is on the order of 10% or more on the energy side. And then capacity, you could think of as kind of a form of hedge against shortage, and that could be 30% or more. And a lot of industrial customers say, I don't need much capacity, I will curtail my business. You know, just tell me when, I think I expect it to happen once a year or something like that. It's in my interest to do that, because I save so much money on all the other megawatt-hours that I'm consuming.
EMP: So, this is not the first time Brattle has done a study like this. You all have done other analyses, right, where about adopting RTO-type markets outside of South Carolina?
JT: That’s right. We have done studies in mostly in the WECC up until this point in time because that's where the RTOs have not already been developed.
EMP: Was there one about North Carolina maybe a year or two ago?
JT: Yeah, we wrote a white paper, myself and a few other colleagues at Brattle wrote a white paper. I wouldn't really put that in the same category as this type of study. In fact, the conclusion of that white paper is we need a real study of markets in South Carolina – or the Carolinas, I should say. So this study for South Carolina that just published is effectively the answer, if you will, of that white paper, or you know, the next step. That white paper really all we did is look at how much did other how much these other places in the country save when they created a market and then apply those same savings to North Carolina and said here's the potential that you could see in a place like North Carolina. So that white paper was really saying here there's potential for savings like there is anywhere in the country that doesn't have a market, a wholesale market, and we should study this more carefully. Basically this was the conclusion of the white paper.
EMP: So, one of the discussions that we're having on the podcast concerns the LMP-style market that PJM has. And you, again, I'll reiterate that you found that melding the Southeast into the PJM market provided the most economic benefit. But there are some who are suggesting that the LMP market is not sufficient – is not adequate to help us go into, or transition into, a clean-energy economy as we're slowly starting to do. Do you all have any thoughts on that? We had Bill Hogan on a few episodes ago and I am going to talk with FERC Commissioner Christie in a month or two. But I was just wondering where your thoughts lie in that regard?
AL: We did not get into that in the South Carolina report.
EMP: I'm away from the report now. I’m asking you for your professional considered opinion.
AL: So I could give my professional considered opinion. I think that we've already seen as we move into a world with more renewables that long-term contracts are rising in importance in terms of financing new entry, relative to how things were in a world that had a lot of mostly gas entry, certainly in the market-based areas like PJM, like New York and New England. And so you might – and then you say okay, these are zero marginal cost resources. LMP will be zero a lot. Therefore, you might conclude let's scrap LMP and just focus on the long-term contracts. I think that's a bad idea. LMP is coupled up with operational incentives that give anybody who's operating in an elastic way with respect to the market, which is mostly supply resources, including batteries – but also a fair number of those industrial customers I was talking about – it gives them all an operational price incentive to do something now. And it will be efficient for society. If the marginal price is zero, any load – what that means, I mean, by definition is any load facing that that price can increase their consumption. And there will be no increase in cost to society. So go ahead and increase that consumption. That's a good thing, charge your car and get your neighbors to charge their cars too and you will pay nothing and it will have been free from a social perspective. So LMP is still really good, but we should recognize that the long-term contracts exist. And we should encourage that and have designs that recognize and encourage that. And we can call those power purchase agreements, which is what a lot of times they are, but it's also all the hedge agreements that exist. And in fact, it would be suitable to have almost all the load covered by some kind of long-term hedge going out one year, many years. And in fact, there's been much discussion since the wholesale markets were invented the ‘90s of why you do or don't have that in different market designs, whether you should mandate it or not. I think there is more discussion of mandating that, especially in the sort of European energy crisis context. I'm seeing it in other regions in the United States as well. The capacity market, as I mentioned, you could look at it as a kind of a hedge against the social costs of shortage, if not the financial costs, and the capacity market is totally mandatory. Loads don't have a choice but to take on this capacity obligation which they can sort of sell back through demand response. So I'd like to see more discussion. I think we are seeing more discussion of this hedge environment. How do we get 20-year hedges and 10-year hedges between loads and generators? Do we need central markets for that? Do we need mandatory markets for that? How can the RTOs help? Do we need any other organizations help with that? And what are the implications for the generators and for the load? I think at the end of the day, and I would guess Bill Hogan would agree, you want a spot market and the spot market is the thing that's ultimately going to direct sort of everything, not just the operations, but the hedge contract is going to be a future expectation of what the spot market is going to be doing. Otherwise, no one would enter into it.
JT: Yeah, the one thing I'd add to that – that was really well said, Andrew – is in addition to those operational incentives that the LMP provides, everybody on the system knows exactly at any moment the cost of their power or the price of the power they’re supplying. It's the transparency of markets. If we didn't have LMPs, or some wholesale market that produced hourly and sub-hourly prices, we could replace that with a world of only contracts, like Andrew described. But those are not transparent. There's tremendous competitive benefits that have come from the wholesale market just because everything is transparent, everything is published. Everybody knows exactly the cost at their location. And are there certainly, like I said, I think there are issues going forward with LMP. That was well said how Andrew described it, given all these monthly zero marginal cost resources that are coming onto the system. But it doesn't mean we want to throw the baby out with the bathwater and you know, throw away the whole wholesale market construct. I think we will learn a lot more in the next 10 years as more and more renewables come onto the system. We'll see how markets perform. We'll see if they're still providing valuable price signals on both the operational timeframe and the longer investment timeframe. We'll see how that continues to work and we can continue to update market designs and fix things. But I would caution against, you know, let's turn our back on 30 years of, you know, well-functioning markets or mostly well-functioning markets with the exception of some really bad designs in the early stages, as you pointed out, Bryan.
AL: I would add, Bryan, if I can, there's no doubt that there also needs to be somewhere between enhancements and major reforms to the ancillary services markets. I think that among other things that we will need higher quantities of ancillary services at various times, probably a longer time horizon, look-ahead time horizon on the ancillary services. There's a lot of active discussions. A lot of people put emphasis on that. I think (FERC) Chairman (Rich) Glick used to say, look, that's really where we should be looking exclusively. I think it's a balance between making sure LMP is right. Things like multi-interval dispatch and, and checking out the uplift rules, making sure the ancillary services markets are going to work for the future and then a relatively new discussion about these long-term contracts, whether they be hedges or energy contracts.
EMP: Well, I'm old enough to remember when all of these markets first started to get established, mainly because I was in the press office at FERC at the time and I was the flak catcher. But I guess they're still doing it. MISO, PJM and the others used to put out an annual report on their value proposition or, i.e., the savings that operating in this way versus the siloed vertically integrated utility model provides. And so I'm thinking so if you added that up over all these years and put a number to that, to quantify it. You guys should get somebody to pay you to do that. I'll break my piggy bank.
JT: I think you're right. I actually think a lot of the markets have stopped doing that, honestly, because it kind of got just redundant. SPP did it for a while. PJM even did it for a while. I don't know if they've done one recently. Andrew might know. But the ones that have caught a lot of attention in the industry these days are out West because they – CAISO does every quarter for their EIM market and the benefits of that are now in the billions.
EMP: So the utilities out West have determined that it's in their interest to cooperate in this way. And that's a change from the time when I was at FERC when they were adamantly opposed to this being forced on them. In the Southeast, this is much slower than the rest of the country. And I'm just wondering, what are the inherent disincentives in the monopoly-regulated pricing system that doesn't give the utilities an incentive to proactively do this?
AL: Yeah, one of the things I've always wondered is, how do the utility cultures come about historically. You actually have seen historical pooling in all the RTO areas going back to PJM in 1927. And we have a little history actually in the South Carolina report, but you know, New York Power Pool and New England Power Pool going back into the ‘70s and into the ‘60s. There was a lot of instability around New York City in the ‘60s. So you kept having these blackouts which prompted that kind of requisite coming together, the history of interconnection. I do think a lot of it is cultural, and not necessarily about where the incentives are coming from, from the regulatory scheme. You know, my view is, this is like, again, back to the pooling, it's like engineers like efficiency. Energy engineers like to see if we bring these systems together, and there's a win-win. And in that kind of win-win situation, there ought to be financial incentives for all the parties. So at a very high level, I'm optimistic in that way.
JT: Yeah, I would only add to that, that I think there are certain aspects of the full range of market reforms – when you start thinking about the Texas model or even the PJM model in certain states in PJM or New England – that do actually, you know, speak directly in a negative way towards the vertically integrated utility, investor-owned, utility business model. Retail competition, generation divestiture, those are things that will affect the bottom line of those companies. But we're not, like I said, we're not recommending those things anytime soon in South Carolina. That's down the road if they choose to go there. But I think there is a little bit of a give-an-inch-take-a-mile mentality that probably infiltrates some of this discussion that you know, if we create a wholesale market, even if it's an SPP-style RTO which is totally vertically integrated still, and particularly regulated at the state level. You know, are we setting ourselves up for 10 years from now a conversation we don't want to have about generation divestiture. I think that's part of the mentality that's, that's happening at the utility level, but I can only speculate about that. I don't really know why opposition is happening.
EMP: Yeah, I was asking you to speculate.
JT: Yeah, that’s fair.
AL: I mean, along those lines, solar is cheap, it's sunny in the Southeast, there's going to be a lot more solar. And I think that the dispatchers and the operators in these balancing authority control rooms are going to start to think about the challenge they're facing balancing the relatively small system with a lot of fluctuations with they've got a local geography and the sun is just flying around as a big cloud comes and puts them puts them into a dark place or puts them in a really bright place. And they're looking around at their region, they're like, you know, I don't love the idea of giving up control given that I have responsibility for reliable service to my customers. But actually the tradeoff on having a small system is worth it, and I'm going to cede it to some sort of central dispatcher. That that kind of operational lever I think is going to become more and more real as that solar just shoots up in the Southeast.
EMP: Gentlemen, I've gone through all of my notes here. As I do with all my guests, I'll throw it back to you for one last swing at the ball here if there's anything you feel we ought to bring up before we say goodbye.
AL: I did – this is this is not by way of recap, just kind of in the weeds – I wanted to point out, LMP, it's not incidental that you pool resources and you have lots of sharing utilities and then LMP comes out of that. When you're sharing a joint operations and a joint dispatch among many utilities sometimes the optimal thing to do would be to, say, tell that utility to bring on all their resources and tell another utility bring on none of their resources. And you'd have to say, okay, how we're going to deal with the money flows here because that utility is going to have to pitch a bunch of money into the pot, because the first utility is spending a bunch on fuel and things like that. And so for example, in PJM, from like, whenever they started joint operations, it could have been 1927, all the way up until 1997, they had a shared-savings approach, which is well, by not running your generators, you saved 100 bucks, you had to pay an extra 200 bucks in fuel. So you take $150 is in the middle and you and you make that transfer from the one utility to the other and they were constantly having to do these shared-savings sort of pairs between all the utilities to figure out who owed what. And it's, it's, you know, it worked okay. It's actually an economist looks at that and says, well, your marginal incentives aren't quite right. The one guy has an incentive to consume less and actually can get more financial gain from it. The other has incentive to consume more. And the LMP environment is a nice way to solve that, basically, agreement by which the different members are going to do their accounting while also sending good price incentives at the margin. So that again, just using an example, when all the resources on the system are wind and solar, the marginal impact of increasing load by a megawatt is zero dollars. You're just going to uncurtail one of the wind or solar resources a little bit. So you get efficient operations of all the generators who are being dispatched. You also get an efficient response from all the generators that are behind-the-meter generators and are looking at those prices, and also efficient response from all the load. So LMP kind of goes together with pooling. It's not mandatory, but it's a really nice way to do it. Even recently, there have been joint-dispatch agreements that use shared savings. For example, Colorado had one up until a few years ago. Other folks are talking about new joint dispatch arrangements that would use shared savings. You don't have to use LMP. But it's a really great tool for that reason.
JT: Yeah, the only other thing I would add maybe, Bryan. I do think there has been a lot of good discussion around our report in South Carolina and this podcast is adding to that, which is great. Thank you for the opportunity to do that. But I do think there is also just a lot of misinformation that has been flying around that I’ve seen in the trade press, too. And a lot of that is – a lot of that I think just comes from people don't understand what we're recommending in the report and what we've actually analyzed. And so partly that's on us. Apparently we didn't explain it well enough. But partly I think people are motivated by, you know, by wanting to confuse the situation a little bit. So, I think, you know, for policymakers and for folks who have their hands on the decision levers here, like, really stepping back and thinking about what we're recommending. And we got into a lot of that in this podcast. We're not recommending generation divestiture. We're not recommending retail choice for residential customers. Those are things that are down the path. We're really just talking about figuring out a way that all the generation owners and all the load-serving entities in the region can come together to share resources where there’s transmission capability to use it the most efficient way at the lowest cost per customer. Then there are different models do that. The RTO is one model, but even within that umbrella term, RTO, there's a wide range of what that means. There's an SPP-style model, there's a capacity market style model like they have a New England, New York and parts of PJM. There's a Texas-style market. California doing something a little bit differently. There's a wide range in that. And then you don't even have to go that far. There are options to access the benefits we estimate here for customers without even going into a full RTO, like an EDAM-style market that they have in the West now or that they will have in the West in the next couple of years. So I really I hope folks really truly digest what's in the report and step back and think about what we're really recommending here and what we're not recommending and kind of have the ability to shut out some of the noise that has come up around the report.
AL: Yeah, just to emphasize, there's so many options. You can take a mix-and-match approach, different ways through governance, different ways to do transmission planning. You can share these things and not share those things. I'm 100% confident that there's a solution out there that will match the political will that's present at the moment. I don't myself know what the solution will be, but we're available to help craft it.
EMP: That seems like a great place to leave things. John Tsoukalis and Andrew Levitt with the Brattle group. Thank you both very much.
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